scholarly journals Effects of the rate of carbon dioxide injection at the initial gas-water contact on the recovery factor

2020 ◽  
pp. 23-30
Author(s):  
О. R. Kondrat ◽  
S. V. Matkivskyi ◽  
О. V. Burachok ◽  
L. І. Haidarova
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Injection Rate ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Carbon Dioxide Injection ◽  
Water Contact ◽  
Gas Recovery ◽  
Production Wells

The process of carbon dioxide injection into the initial gas-water contact with different rates of its injection, using a 3D model of a gas condensate reservoir, has been investigated. Calculations were carried out for one well injection rate of non-hydrocarbon gas: 40, 50, 60, 70, 80, 90 th.m3/day. According to the calculated results, it has been found that with an increased rate of the carbon dioxide injection into a productive reservoir, the operation duration of production wells decreases until the moment of the carbon dioxide breakthrough. Based on the techno-logical indicators’ analysis of the gas condensate reservoir’s development, it has been found that the introduction of the carbon dioxide injecting technology leads to a reduction in the production of formation water. Due to the injec-tion of non-hydrocarbon gases, a hydrodynamic barrier is created on the initial gas-water contact boundary, which decreases the water influx. Also, the introduction of carbon dioxide injection technology will additionally create an artificial barrier between water and natural gas, which blocks the selective water encroaching and thereby ensure stable waterless operation of production wells. Based on the conducted calculations, the main dependencies have been derived and the corresponding patterns between them have been established. According to the results of the statistical processing of the calculated data, the optimal carbon dioxide injection rate has been determined. At the time of the carbon dioxide breakthrough into the producing well, its optimal well injection rate is 58.17 th.m3/day. The ultimate gas recovery factor for the optimal carbon dioxide injection rate is 63.29 %. Under the same condi-tions during depletion, the ultimate natural gas recovery factor is 53.98%. The results of the carried out studies indicate the technological efficiency of carbon dioxide injection into the initial gas-water contact in order to slow down the formation water encroaching into productive reservoir.

scholarly journals Effects of the rate of natural gas production on the recovery factor during carbon dioxide injection at the initial gas-water contact

2021 ◽  
Vol 1 (3(57)) ◽  
pp. 6-11
Author(s):  
Serhii Matkivskyi
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Production ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Formation Water ◽  
Hydrocarbon Gases ◽  
Water Contact ◽  
Natural Gas Production ◽  
Gas Recovery

The object of research is gas condensate reservoirs, which is being developed under the conditions of the manifestation of the water drive of development and the negative effect of formation water on the process of natural gas production. The results of the performed theoretical and experimental studies show that a promising direction for increasing hydrocarbon recovery from fields at the final stage of development is the displacement of natural gas to producing wells by injection non-hydrocarbon gases into productive reservoirs. The final gas recovery factor according to the results of laboratory studies in the case of injection of non-hydrocarbon gases into productive reservoirs depends on the type of displacing agent and the level heterogeneity of reservoir. With the purpose update the existing technologies for the development of fields in conditions of the showing of water drive, the technology of injection carbon dioxide into productive reservoirs at the boundary of the gas-water contact was studied using a digital three-dimensional model of a gas condensate deposit. The study was carried out for various values of the rate of natural gas production. The production well rate for calculations is taken at the level of 30, 40, 50, 60, 70, 80 thousand m3/day. Based on the data obtained, it has been established that an increase in the rate of natural gas production has a positive effect on the development of a productive reservoir and leads to an increase in the gas recovery factor. Based on the results of statistical processing of the calculated data, the optimal value of the rate of natural gas production was determined when carbon dioxide is injected into the productive reservoir at the boundary of the gas-water contact is 55.93 thousand m3/day. The final gas recovery factor for the optimal natural gas production rate is 64.99 %. The results of the studies carried out indicate the technological efficiency of injecting carbon dioxide into productive reservoirs at the boundary of the gas-water contact in order to slow down the movement of formation water into productive reservoirs and increase the final gas recovery factor.

scholarly journals Studying the influence of the carbon dioxide injection period duration on the gas recovery factor during the gas condensate fields development under water drive

2021 ◽  
Vol 15 (2) ◽  
pp. 95-101
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat
Keyword(s):  
Carbon Dioxide ◽  
Gas Condensate ◽  
Recovery Factor ◽  
Water Inflow ◽  
Formation Water ◽  
Carbon Dioxide Injection ◽  
Water Contact ◽  
Hydrocarbon Recovery ◽  
Injection Period ◽  
Gas Recovery

Purpose. Studying the process of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors. Methods. To assess the influence on gas recovery factor of the duration of carbon dioxide injection period at the initial gas-water contact, a reservoir development is studied using the main Eclipse and Petrel hydrodynamic modeling tools of the Schlumberger company on the example of a hypothetical three-dimensional model of a gas-condensate reservoir. Findings. The dependence of the main technological indicators of reservoir development on the duration of the carbon dioxide injection period at the initial gas-water contact has been determined. It has been revealed that an increase in the duration of the non-hydrocarbon gas injection period leads to a decrease in the formation water cumulative production. It has been found that when injecting carbon dioxide, an artificial barrier is created due to which the formation water inflow into the gas-saturated intervals of the productive horizon is partially blocked. The final gas recovery factor when injecting carbon dioxide is 61.98%, and when developing the reservoir for depletion – 48.04%. The results of the research performed indicate the technological efficiency of carbon dioxide injection at the boundary of the initial gas-water contact in order to slow down the formation water inflow into producing reservoirs and increase the final hydrocarbon recovery factors for the conditions of a particular field. Originality. The optimal value of duration of the carbon dioxide injection period at the initial gas-water contact has been determined, which is 16.32 months based on the statistical processing of calculated data for the conditions of a particular field. Practical implications. The use of the results makes it possible to improve the existing technologies for the gas condensate fields development under water drive and to increase the final hydrocarbon recovery factor.

scholarly journals Investigation of the influence of the carbon dioxide (CO2) injection rate on the activity of the water pressure system during gas condensate fields development

2021 ◽  
Vol 230 ◽  
pp. 01011
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat ◽  
Oleksandr Burachok
Keyword(s):  
Carbon Dioxide ◽  
Water Pressure ◽  
Gas Production ◽  
Gas Condensate ◽  
Co2 Injection ◽  
Final Decision ◽  
Water Production ◽  
Carbon Dioxide Injection ◽  
Pressure System ◽  
Water Contact

The development of gas condensate fields under the conditions of elastic water drive is characterized by uneven movement of the gas-water. Factors of hydrocarbon recovery from producing reservoirs which are characterized by the active water pressure drive on the average make up 50-60%. To increase the efficiency of fields development, which are characterized by an elastic water drive, a study of the effect of different volumes of carbon dioxide injection at the gas-water contact on the activity of the water pressure system and the process of flooding producing wells was carried out. Using a three-dimensional model, the injection of carbon dioxide into wells located at the boundary of gas-water contact with flow rates from 20 to 500 thousand m3/day was investigated. Analyzing the simulation data, it was found that increasing the volume of carbon dioxide injection provides an increase in accumulated gas production and a significant reduction in water production. The main effect of the introduction of this technology is achieved by increasing the rate of carbon dioxide injection to 300 thousand m3/day. The set injection rates allowed us to increase gas production by 67% and reduce water production by 83.9% compared to the corresponding indicators without injection of carbon dioxide. Taking into account above- mentioned, the final decision on the introduction of carbon dioxide injection technology and optimal technological parameters of producing and injection wells operation should be made on the basis of a comprehensive technical and economic analysis using modern methods of the hydrodynamic modeling of reservoir systems.

Research on Corrosion of Well-Bore Tube and Anticorrosive Measure of Tazhong-1 Gas Field

2011 ◽  
Vol 108 ◽  
pp. 308-313 ◽  
Author(s):  
Shan Fa Tang ◽  
Xue Yang ◽  
Da Wei Wu
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
Corrosion Inhibitors ◽  
Produced Water ◽  
Formation Water ◽  
Well Bore ◽  
Gas Field ◽  
Production Wells ◽  
Sulfide Corrosion

Natural gas of Tazhong-1 gas field contains 7.7% carbon dioxide and 2.31% hydrogen sulfide, and produced water salinity is up to 140000mg/L,the well-bore tube has seriously potential corrosion destructive with natural gas being exploited. Based on the corrosion type partition of down-hole tube for eighteen production wells of Tazhong-1 gas field, P110,P110S and P110SS corrosion behavior were investigated under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide/carbon dioxide, and corrosion inhibitors were chosen to meet need of anticorrosion of Tazhong-1 gas field. The results show that fifteen wells in eighteen production wells belong to hydrogen sulfide corrosion of both hydrogen sulfide and carbon dioxide influence. Other wells are singular carbon dioxide corrosion. The most severe corrosion of three types of down-hole tubes all occurs at 90°C in both corrosion media, and their corrosion resistance order is respectively P110>P110S>P110SS and P110S>P110SS>P110 under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide and carbon dioxide. The selected anti-temperature corrosion inhibitors (YU-1、YU-4) can control the corrosion rate of three types of down-hole tubular goods within 0.076mm/a in simulated formation water media with carbon dioxide (PCO2=0.08～4.64MPa) or hydrogen sulfide and carbon dioxide (PH2S/Pco2=1.3/4.64Mpa) while added amount of the inhibitor is 120～300mg/L or 200mg/L. All of these provide technical support for safe and fast development of Tazhong-1 gas field.

scholarly journals The influence of nitrogen injection duration at the initial gas-water contact on the gas recovery factor

2021 ◽  
Vol 1 (6 (109)) ◽  
pp. 77-84
Author(s):  
Serhii Matkivskyi ◽  
Oleksandr Kondrat
Keyword(s):  
Recovery Factor ◽  
Water Production ◽  
Reservoir Water ◽  
Water Contact ◽  
Gas Recovery ◽  
Nitrogen Injection ◽  
Injection Duration ◽  
Study Results ◽  
Production Wells ◽  
Hydrocarbon Gas

This paper reports a study that employed a digital three-dimensional model of the gas condensate reservoir to investigate the process of nitrogen injection at the boundary of initial gas-water contact at different values of the injection duration. The calculations were performed for 5, 6, 8, 10, 12 and 14 months injection duration. Based on the modeling results, it was found that increasing the duration of the nitrogen injection decreases the operation time of production wells until the breakthrough of non-hydrocarbon gas. Based on the analysis of the technological indicators of reservoir development, it was established that the introduction of technology of the nitrogen injection into a reservoir ensures a reduction in the volume of reservoir water production. The cumulative water production at the time of nitrogen breakthrough to the production wells at the nitrogen injection duration of 5 months is 197,3 thousand m3; of 14 months – 0,038 m3. According to the results from the statistical treatment of estimation data, the optimal value for the nitrogen injection duration was determined, which is 8,04 months. The ultimate gas recovery factor for the optimal period of the non-hydrocarbon gas injection is 58,11 %, and in the development of a productive reservoir for depletion – 34,6 %. Based on the research results, the technological efficiency of nitrogen injection into a productive reservoir has been determined at the boundary of initial gas-water contact in order to slow the movement of reservoir water into gas-saturated horizons. This study results allow the improvement of the existing technologies of hydrocarbon fields development under conditions of water drive. The use of the results of the research carried out in production will make it possible to reduce the volume of cumulative water production and increase the ultimate gas recovery factors to 23,51 %

Numerical simulation and optimization of CO2 enhanced gas recovery in homogeneous and vertical heterogeneous reservoir models

2021 ◽  
pp. 1-36
Author(s):  
Shuyang Liu ◽  
Ramesh Agarwal ◽  
Baojiang Sun
Keyword(s):  
Natural Gas ◽  
Injection Rate ◽  
Injection Time ◽  
Upward Migration ◽  
Enhanced Gas Recovery ◽  
Simulation And Optimization ◽  
Heterogeneous Reservoirs ◽  
Gas Recovery ◽  
Heterogeneous Reservoir ◽  
Optimal Injection

Abstract CO2 enhanced gas recovery (CO2-EGR) is a promising, environment-friendly technology with simultaneously sequestering CO2. The goals of this paper are to conduct simulations of CO2-EGR in both homogeneous and heterogeneous reservoirs to evaluate effects of gravity and reservoir heterogeneity, and to determine optimal CO2 injection time and injection rate for achieving better natural gas recovery by employing a genetic algorithm integrated with TOUGH2. The results show that gravity segregation retards upward migration of CO2 and promotes horizontal displacement efficiency, and the layers with low permeability in heterogeneous reservoir hinder the upward migration of CO2. The optimal injection time is determined as the depleted stage, and the corresponding injection rate is optimized. The optimal recovery factors are 62.83 % and 64.75 % in the homogeneous and heterogeneous reservoirs (804.76 m × 804.76 m × 45.72 m), enhancing production by 22.32 × 103 and 23.00 × 103 t of natural gas and storing 75.60 × 103 and 72.40 × 103 t CO2 with storage efficiencies of 70.55 % and 67.56 %, respectively. The cost/benefit analysis show that economic income of about 8.67 and 8.95 million USD can be obtained by CO2-EGR with optimized injection parameters respectively. This work could assist in determining optimal injection strategy and economic benefits for industrial scale gas reservoirs.

Carbon Dioxide in a Natural Gas-Condensate System

1946 ◽  
Vol 38 (5) ◽  
pp. 530-534 ◽  
Author(s):  
Fred H. Poettmann ◽  
Donald L. Katz
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Gas Condensate ◽  
Condensate System
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